Document

EX-99.2 3 a2021sigreportingpackage.htm EX-99.2 Document

Exhibit 99.2

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

FINANCIAL STATEMENTS

For the year ended December 31, 2021

Contents


			Page Number
Audited Financial Statements
Definitions			1
Independent Auditor's Report			3
Balance Sheets			5-6
Statements of Income			7
Statements of Cash Flows			8
Statements of Common Shareholder's Equity			9
Notes to the Financial Statements			10-35



DEFINITIONS
ACE			Affordable Clean Energy
AFUDC			Allowance for funds used during construction
AMA			Asset Management Agreement
ARO			Asset Retirement Obligation
ARP			Alternative Revenue Program
ASC			Accounting Standards Codification
ASU			Accounting Standard Update
BTA			Build Transfer Agreement
Capital Dynamics			Capital Dynamics, Inc., a Delaware corporation
CCR			Coal Combustion Residuals
CECA			Clean Energy Cost Adjustment
CEI North			Indiana Gas Company, Inc. or CenterPoint Energy Indiana North
CEOH			Vectren Energy Delivery of Ohio, Inc. or CenterPoint Energy Ohio
CERC			CERC Corp., together with its subsidiaries
COVID-19			Novel coronavirus disease 2019, and any mutations or variants thereof, and related global outbreak that was subsequently declared a pandemic by the World Health Organization
CODM			Chief Operating Decision Maker who is the Company's President
CPCN			Certificate of Public Convenience and Necessity
CPP			Clean Power Plan
CSIA			Compliance and System Improvement Adjustment
DRR			Distribution Replacement Rider
DSMA			Demand Side Management Adjustment
ECA			Environmental Cost Adjustment
EEFC			Energy Efficiency Funding Component
EEFR			Energy Efficiency Funding Rider
EPA			Environmental Protection Agency
FASB			Financial Accounting Standards Board
February 2021 Winter Storm Event			The extreme and unprecedented winter weather event in February 2021 resulting in electricity generation supply shortages, including in Texas, and natural gas supply shortages and increased wholesale prices of natural gas in the United States, primarily due to prolonged freezing temperatures.
FERC			Federal Energy Regulation Commission
GAAP			Generally Accepted Accounting Principles
GHG			Greenhouse gases
IDEM			Indiana Department of Environmental Management
Infrastructure Services			Provided underground pipeline construction and repair services through VISCO and its wholly-owned subsidiaries, Miller Pipeline, LLC and Minnesota Limited, LLC
IURC			Indiana Utility Regulatory Commission
MGP			Manufactured gas plant
MISO			Midcontinent Independent System Operator
MW			megawatts
NYMEX			New York Mercantile Exchange
Posey Solar			Posey Solar, LLC, a Delaware limited liability company
PowerTeam Services			PowerTeam Services, LLC, a Delaware limited liability company, now known as Artera Services, LLC
PPA			Power purchase agreement
PRP			Potentially responsible parties
PUCO			Public Utilities Commission of Ohio


RCRA			Resource Conservation and Recovery Act of 1976
ROU			Right of use
Scope 1 emissions			Direct source of emissions from a company’s operations
Scope 2 emissions			Indirect source of emissions from a company’s energy usage
Scope 3 emissions			Indirect source of emissions from a company’s end-users
SERP			Supplemental Executive Retirement Plan
SRC			Sales Reconciliation Component
TCJA			Tax Cuts and Jobs Acts
TDSIC			Transmission, Distribution and Storage System Improvement Charge
Tenaska			Tenaska Wind Holdings, LLC
TSCR			Tax Savings Credit Rider
VISCO			Vectren Infrastructure Services Corporation, previously a wholly-owned subsidiary of Vectren, and which was sold pursuant to the Securities Purchase Agreement, dated as of February 3 2020, by and among VUSI, PowerTeam Services and, solely for purposes of Section 10.17 of the Securities Purchase Agreement, Vectren
VRP			Voluntary Remediation Program
VUSI			Vectren Utility Services, Inc., a wholly-owned subsidiary of Vectren

INDEPENDENT AUDITOR'S REPORT

To the Board of Directors of Southern Indiana Gas and Electric Company:

Opinion

We have audited the financial statements of Southern Indiana Gas and Electric Company (the “Company”) (a wholly owned subsidiary of Vectren Utility Holdings, Inc.), which comprise the balance sheets as of December 31, 2021 and 2020, and the related statements of income, common shareholder’s equity, and cash flows for the years then ended, and the related notes to the financial statements (collectively referred to as the "financial statements").

In our opinion, the accompanying financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

Basis for Opinion

We conducted our audits in accordance with auditing standards generally accepted in the United States of America (GAAS). Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Audit of the Financial Statements section of our report. We are required to be independent of the Company and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Responsibilities of Management for the Financial Statements

Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

In preparing the financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for one year after the date that the financial statements are issued.

Auditor’s Responsibilities for the Audit of the Financial Statements

Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the financial statements.

In performing an audit in accordance with GAAS, we:

•Exercise professional judgment and maintain professional skepticism throughout the audit.

•Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements.

•Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. Accordingly, no such opinion is expressed.

•Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the financial statements.

•Conclude whether, in our judgment, there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for a reasonable period of time.

We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control-related matters that we identified during the audit.

Other Information Included in the Annual Report

Management is responsible for the other information included in the annual report. The other information comprises the information included in the annual report but does not include the financial statements and our auditor’s report thereon. Our opinion on the financial statements does not cover the other information, and we do not express an opinion or any form of assurance thereon.

In connection with our audits of the financial statements, our responsibility is to read the other information and consider whether a material inconsistency exists between the other information and the financial statements, or the other information otherwise appears to be materially misstated. If, based on the work performed, we conclude that an uncorrected material misstatement of the other information exists, we are required to describe it in our report.



/s/ DELOITTE & TOUCHE LLP
Indianapolis, Indiana
March 16, 2022

FINANCIAL STATEMENTS

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS


	December 31, 2021		December 31, 2020
	(in millions)
ASSETS
Current Assets
Cash & cash equivalents	$	2	$	3
Accounts receivable - less allowance for credit losses of $3 and $3, respectively	53		48

Accrued unbilled revenues - less allowance for credit losses of $-0- and $-0-, respectively	28		25
Inventories	72		96
Regulatory assets	24		—
Prepaid expenses and other current assets	13		8
Total current assets	192		180




Property, Plant and Equipment, net	2,615		2,399
Other Assets:
Other investments	—		8
Goodwill	6		6
Regulatory assets	193		169
Other non-current assets	52		45
Total other assets	251		228
Total Assets	$	3,058	$	2,807

The accompanying notes are an integral part of these financial statements

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS


	December 31, 2021		December 31, 2020
	(in millions)
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities:
Accounts payable	$	78	$	56
Accounts payable - affiliated companies	19		22

Accrued liabilities	62		37
Notes payable - affiliated companies	69		72
Current maturities of long-term debt - third parties	5		—
Current maturities of long-term debt - affiliated companies	—		55
Total current liabilities	233		242
Other Liabilities:
Deferred income taxes	261		267
Regulatory liabilities	284		260
Other non-current liabilities	192		146
Total other liabilities	737		673
Long-term Debt:
Long-term debt - third parties, net of current maturities	288		293
Long-term debt - affiliated companies, net of current maturities	640		515
Total long-term debt	928		808
Commitments and Contingencies (Note 8)
Common shareholder's equity:
Common stock (no par value)	433		$	433
Retained earnings	727		651

Total common shareholder's equity	1,160		1,084
Total Liabilities and Shareholder's Equity	$	3,058	$	2,807

The accompanying notes are an integral part of these financial statements

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF INCOME


	Year Ended December 31,
	2021		2020
	(in millions)
Revenues:
Electric utility revenues	$	629	$	554
Gas utility revenues	134		100
Total	763		654
Expenses:
Fuel and purchased power	186		147
Utility natural gas	55		28
Operation and maintenance	215		216
Depreciation and amortization	135		120
Taxes other than income taxes	20		20
Total operating expenses	611		531
Operating Income	152		123
Other Income (Expense):
Interest expense	(32)		(32)
Other income, net	7		11
Income Before Income Taxes	127		102
Income tax expense	21		20
Net Income	$	106	$	82

The accompanying notes are an integral part of these financial statements

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2021		2020
Cash Flows from Operating Activities:	(in millions)
Net income	$	106	$	82
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization	135		120
Deferred income taxes and investment tax credits	19		43
Expense portion of pension and postretirement benefit cost	3		5
Changes in working capital accounts:
Accounts receivable & accrued unbilled revenue	(8)		(6)
Accounts receivable/payable, affiliates	(3)		—
Accounts payable	8		78
Inventories	24		(10)
Net regulatory assets and liabilities	(38)		(27)
Other current assets and liabilities	18		6
Other assets and liabilities	4		(12)
Other operating activities, net	(1)		2
Net cash provided by operating activities	267		281
Cash Flows from Investing Activities:
Capital expenditures	(309)		(299)
Other investing activities, net	4		4
Net cash used in investing activities	(305)		(295)
Cash Flows from Financing Activities:
Net change in short-term notes payable - affiliated companies	(3)		—
Proceeds from long-term notes payable - affiliated companies	125		196
Payment of long-term debt - affiliated companies	(55)		—
Payment of long-term debt - third parties	—		(114)
Dividends to parent	(30)		(69)

Net cash provided by financing activities	37		13
Net change in cash & cash equivalents	(1)		(1)
Cash & cash equivalents at beginning of period	3		4
Cash & cash equivalents at end of period	$	2	$	3

The accompanying notes are an integral part of these financial statements

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF COMMON SHAREHOLDER'S EQUITY


	Common Stock		Retained Earnings		Total
	(in millions)
Balance at January 1, 2020	$	433	$	638	$	1,071
Net income			82		82

Common stock:

Dividends to VUHI			(69)		(69)
Balance at December 31, 2020	$	433	$	651	$	1,084
Net income			106		106

Common stock:

Dividends to VUHI			(30)		(30)
Balance at December 31, 2021	$	433	$	727	$	1,160

The accompanying notes are an integral part of these financial statements

SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

NOTES TO THE FINANCIAL STATEMENTS

(1)Organization and Nature of Operations

Southern Indiana Gas and Electric Company (the Company or CEI South), an Indiana corporation, provides energy delivery services to 150,382 electric customers and 114,671 gas customers located near Evansville in southwestern Indiana. Of these customers, 87,004 receive combined electric and gas distribution services. The Company also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. The Company is a direct, wholly owned subsidiary of Vectren Utility Holdings, Inc. (VUHI or the Company's parent). VUHI is a direct, wholly owned subsidiary of Vectren Corporation (Vectren). Vectren, a wholly owned subsidiary of CenterPoint Energy, Inc. (collectively with its subsidiaries, CenterPoint Energy), is an energy holding company headquartered in Evansville, Indiana.

(2)Summary of Significant Accounting Policies

(a) Use of Estimates

In applying its accounting policies, the Company makes judgments, assumptions, and estimates that affect the amounts reported in these financial statements and related footnotes. Examples of transactions for which estimation techniques are used include valuing deferred tax obligations, unbilled revenue, uncollectible accounts, regulatory assets and liabilities, asset retirement obligations, and derivatives and other financial instruments. Estimates also impact the depreciation of property, plant and equipment and the testing of goodwill and other assets for impairment. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Actual results could differ from current estimates.

(b) Cash & Cash Equivalents

Highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents. Cash and cash equivalents are stated at cost plus accrued interest to approximate fair value.

Accounts receivable are recorded at the invoiced amount and do not bear interest. Management reviews historical write-offs, current available information, and reasonable and supportable forecasts to estimate and establish allowance for credit losses. Account balances are charged off against the allowance when management determines it is probable the receivable will not be recovered. See Note 5 for further information about regulatory deferrals of bad debt expense related to COVID-19.

(d) Inventories

In most circumstances, the Company’s inventory components are recorded using an average cost method; however, natural gas in storage is recorded using the Last In – First Out (LIFO) method. Inventory is valued at historical cost consistent with ratemaking treatment. Materials and supplies are recorded as inventory when purchased and subsequently charged to expense or capitalized to plant when installed.

Inventories consist of the following:


	December 31,
	2021		2020
	(in millions)
Materials & supplies	$	37	$	33
Fuel (coal and oil) for electric generation	13		44
Gas in storage – at LIFO cost	22		19

Total inventories	$	72	$	96

Based on the average cost of gas purchased during December 2021 and 2020, the cost of replacing gas in storage carried at LIFO cost is less than the carrying value at December 31, 2021 and 2020 by approximately $2 million and $7 million, respectively.

All other inventories are carried at average cost. The Company sources most of its coal supply from a single third party and also purchases most of its natural gas from a different single third party. Rates charged to natural gas customers contain a gas cost adjustment clause and electric rates contain a fuel adjustment clause that allow for the timely adjustment in charges to reflect changes in the cost of gas and cost for fuel.

(e) Long-lived Assets and Goodwill

The Company records property, plant and equipment at historical cost and expenses repair and maintenance costs as incurred.

The Company periodically evaluates long-lived assets, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. For rate regulated businesses, recoverability of long-lived assets is assessed by determining if a capital disallowance from a regulator is probable through monitoring the outcome of rate cases and other proceedings. No long-lived asset impairments were recorded in 2021 or 2020.

The Company performs goodwill impairment tests at least annually and evaluates goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. The Company recognizes a goodwill impairment by the amount a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill within that reporting unit. The Company includes deferred tax assets and liabilities within its reporting unit’s carrying value for the purposes of annual and interim impairment tests, regardless of whether the estimated fair value reflects the disposition of such assets and liabilities. Goodwill is reported in the Company's Natural Gas reporting segment.

The Company performed the annual goodwill impairment tests in the third quarter of 2021 and determined that no goodwill impairment charge was required.

(f) Depreciation and Amortization Expense

The Company computes depreciation and amortization using the straight-line method based on economic lives or regulatory-mandated recovery periods. Amortization expense includes amortization of certain regulatory assets.

The Company’s portion of jointly owned property, plant and equipment, along with that plant’s related operating expenses, is presented in these financial statements in proportion to the ownership percentage.

(g) Capitalization of AFUDC

The Company capitalizes AFUDC as a component of projects under construction and amortizes it over the assets’ estimated useful lives once the assets are placed in service. AFUDC represents the composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction as the Company applies the guidance for accounting for regulated operations. Although AFUDC increases both property, plant and equipment and earnings, it is realized in cash when the assets are included in rates.


	Year Ended December 31,
	2021		2020
	(in millions)
AFUDC – borrowed funds	$	4	$	5
AFUDC – equity funds (1)	4		7

(1)Included in Other income, net on the Company's Statements of Income.

(h) Regulation

Retail public utility operations are subject to regulation by the IURC. The Company is subject to FERC regulation as an electric public utility. The Company’s accounting policies give recognition to the ratemaking and accounting practices authorized by this agency.

(i) Refundable or Recoverable Gas Costs & Cost of Fuel & Purchased Power

All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings. The Company records any under or over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding regulatory asset or liability is recorded until the under or over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel and purchased power for electric generation is charged to operating expense when consumed.

(j) Regulatory Assets & Liabilities

Regulatory assets represent certain incurred costs, which will result in probable future cash recoveries from customers through the ratemaking process. Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. The Company continually assesses the recoverability of costs recognized as regulatory assets and the ability to recognize new regulatory assets associated with its regulated utility operations. The Company records pre-tax expense for (i) probable disallowances of capital investments and (ii) customer refund obligations and costs deferred in regulatory assets when recovery of such amounts is no longer considered probable. Given the current regulatory environment in its jurisdictions, the Company believes such accounting for regulatory assets and regulatory liabilities is appropriate.

The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings. The Company records amounts collected in advance of expenditure as a regulatory liability.

(k) Asset Retirement Obligations

A portion of removal costs related to interim retirements of gas utility pipeline and electric utility poles, and reclamation activities meet the definition of an ARO. The Company records the fair value of a liability for a legal ARO in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. The liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, regulatory assets and liabilities result when accretion and amortization is adjusted to match rates established by regulators and any gain or loss is subject to deferral.

(l) Energy Contracts & Derivatives

The Company will periodically execute derivative contracts in the normal course of operations while buying and selling commodities to be used in operations, optimizing its generation assets, and managing risk. A derivative is recognized on the balance sheet as an asset or liability measured at its fair market value and the change in the derivative's fair market value depends on the intended use of the derivative and resulting designation.

When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale (NPNS), it is exempt from mark-to-market accounting. Such energy contracts include Real Time and Day Ahead purchase and sale contracts with the MISO, certain natural gas purchases, and wind farm and other electric generating contracts.

When the Company engages in energy contracts and financial contracts that are derivatives and are not subject to the NPNS or other exclusions, such contracts are recorded at fair value as current or non-current assets or liabilities depending on their value and when the contracts are expected to be settled. Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the Balance Sheets. The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to regulatory accounting treatment. The offset to contracts affected by regulatory accounting treatment, which include most of the Company's executed energy and financial contracts, are marked to market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources or from internal models. As of and for the periods presented, derivative activity, other than NPNS, is not material to these financial statements.

(m) Environmental Costs

The Company expenses or capitalizes environmental expenditures, as appropriate, depending on their future economic benefit. The Company expenses amounts that relate to an existing condition caused by past operations that do not have future economic

benefit. The Company records undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.

(n) Income Taxes

The Company is included in CenterPoint Energy's consolidated federal income tax return. Vectren and certain subsidiaries are also included in various unitary or consolidated state income tax returns with CenterPoint Energy. In other state jurisdictions, Vectren and certain subsidiaries continue to file separate state tax returns. The Company calculates the provision for income taxes and income tax liabilities for each jurisdiction using a separate return method.

The Company uses the asset and liability method of accounting for deferred income taxes. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. A valuation allowance is established against deferred tax assets for which management believes realization is not considered to be more likely than not. The Company recognizes interest and penalties as a component of income tax expense (benefit), as applicable, in their respective Statements of Income.

To the extent certain excess deferred income taxes of the Company’s rate-regulated subsidiaries may be recoverable or payable through future rates, regulatory assets and liabilities have been recorded, respectively.

Investment tax credits are deferred and amortized to income over the approximate lives of the related property.

(o) Revenue Policy

Revenue is recognized when obligations under the terms of a contract with the customer are satisfied. Revenue is measured as the amount of consideration the Company expects to receive in exchange for transferring goods or providing services. The satisfaction of performance obligation occurs when the transfer of goods and services occur, which may be at a point in time or over time, resulting in revenue being recognized over the course of the underlying contract or at a single point in time based upon the delivery of services to customers.

(p) MISO Transactions

With the IURC’s approval, the Company is a member of the MISO, a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midcontinent region and maintains operational control over the Company’s electric transmission facilities as well as other utilities in the region. The Company is an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.

MISO-related purchase and sale transactions are recorded using settlement information provided by the MISO. These purchase and sale transactions are accounted for on at least a net hourly position, meaning net purchases within that interval are recorded on the Company's Statements of Income in Utility natural gas and Fuel and purchased power, and net sales within that interval are recorded on the Company's Statements of Income in Natural gas utility and Electric utility revenues. On occasion, prior period transactions are resettled outside the routine process due to a change in the MISO’s tariff or a material interpretation thereof. Expenses associated with resettlements are recorded once the resettlement is probable and the resettlement amount can be estimated. Revenues associated with resettlements are recognized when the amount is determinable and collectability is reasonably assured.

The Company also receives transmission revenue that results from other members’ use of the Company’s transmission system. These revenues are also included in Electric utility revenues. Generally, these transmission revenues along with costs charged by the MISO are considered components of base rates and any variance from that included in base rates is recovered from / refunded to retail customers through tracking mechanisms.

(q) Utility Receipts Taxes

A portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $9 million in 2021 and $8 million in 2020. Expense associated with utility receipts taxes are recorded as a component of Taxes other than income taxes.

(r) Fair Value Measurements

Certain assets and liabilities are valued and disclosed at fair value. Nonfinancial assets and liabilities include the initial measurement of an asset retirement obligation or the use of fair value in goodwill, intangible assets, and long-lived assets impairment tests. FASB guidance provides the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are described as follows:


Level 1			Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets that the Company has the ability to access.
Level 2			Inputs to the valuation methodology include · quoted prices for similar assets or liabilities in active markets; · quoted prices for identical or similar assets or liabilities in inactive markets; · inputs other than quoted prices that are observable for the asset or liability; · inputs that are derived principally from or corroborated by observable market data by correlation or other means If the asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability.
Level 3			Inputs to the valuation methodology are unobservable and significant to the fair value measurement.

The asset or liability’s fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used maximize the use of observable inputs and minimize the use of unobservable inputs.

(s) Other Significant Policies

Included elsewhere in these notes are significant accounting policies related to retirement plans and other postretirement benefits, intercompany allocations and income taxes (Note 6).

(3)Revenue

In accordance with ASC 606, revenue is recognized when a customer obtains control of promised goods or services. The amount of revenue recognized reflects the consideration to which the Company expects to be entitled to receive in exchange for these goods or services.

The Company determines that disaggregating revenue into certain categories achieves the disclosure objective to depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. These material revenue generating categories, as disclosed in Note 12, include: Natural Gas and Electric.

The Company provides commodity service to customers at rates, charges, and terms and conditions included in tariffs approved by regulators. The Company’s utilities bill customers monthly and have the right to consideration from customers in an amount that corresponds directly with the performance obligation satisfied to date. The performance obligation is satisfied and revenue is recognized upon the delivery of services to customers. The Company records revenues for services and goods delivered but not billed at the end of an accounting period in Accrued unbilled revenues, derived from estimated unbilled consumption and tariff rates or in a regulatory asset, as applicable. The Company's revenues are also adjusted for the effects of regulation including tracked operating expenses, infrastructure replacement mechanisms, decoupling mechanisms, and lost margin recovery. Decoupling and lost margin recovery mechanisms are considered ARPs, which are excluded from the scope of ASC 606. Customers are billed monthly and payment terms, set by the regulator, require payment within a month of billing. The Company's revenues are not subject to significant returns, refunds, or warranty obligations.

In the following table, the Company's revenue is disaggregated by Reportable segment and major source.


	Year Ended December 31, 2021
	Electric		Natural Gas		Total
	(in millions)
Revenue from contracts	$	609	$	132	$	741
Other (1)	20		2		22


Total Revenues	$	629	$	134	$	763

	Year Ended December 31, 2020
	Electric		Natural Gas		Total
	(in millions)
Revenue from contracts	$	537	$	104	$	641
Other (1)	17		(4)		13
Total Revenues	$	554	$	100	$	654

(1)Primarily consists of income from ARPs. ARPs are contracts between the utility and its regulators, not between the utility and a customer. The Company recognizes ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period.

Revenues from Contracts with Customers

Contract Balances. The Company does not have any material contract balances (right to consideration for services already provided or obligations to provide services in the future for consideration already received). Substantially all the Company's accounts receivable results from contracts with customers.

The opening and closing balances of the Company's accounts receivable and other accrued unbilled revenue are as follows:


	Accounts Receivable		Other Accrued Unbilled Revenues
	(in millions)
Opening balance as of December 31, 2020	$	48	$	25
Closing balance as of December 31, 2021	53		28
Increase	$	5	$	3

Allowance for Credit Losses and Bad Debt Expense

The Company segregates financial assets that fall under the scope of Topic 326, primarily trade receivables due in one year or less, into portfolio segments based on shared risk characteristics, such as geographical location and regulatory environment, for evaluation of expected credit losses. Historical and current information, such as average write-offs, are applied to each portfolio segment to estimate the allowance for losses on uncollectible receivables. Additionally, the allowance for losses on uncollectible receivables is adjusted for reasonable and supportable forecasts of future economic conditions, which can include changing weather, commodity prices, regulations, and macroeconomic factors, among others. For a discussion of regulatory deferrals related to COVID-19, see Note 5.

The table below summarizes the Company's bad debt expense amounts for 2021 and 2020, net of regulatory deferrals, including those related to COVID-19:


	Year Ended December 31,
	2021		2020
	(in millions)
Bad debt expense	$	2	$	3

(4)Property, Plant and Equipment

(a) Property, Plant and Equipment

Property, plant and equipment includes the following:


		December 31, 2021						December 31, 2020
	Weighted Average Useful Lives	Property, Plant and Equipment, Gross		Accumulated Depreciation and Amortization		Property, Plant and Equipment, Net		Property, Plant and Equipment, Gross		Accumulated Depreciation and Amortization		Property, Plant and Equipment, Net
	(in years)	(in millions)
Electric transmission and distribution	35	$	1,857	$	1,018	$	839	$	1,631	$	855	$	776
Electric generation	26	2,013		750		1,263		1,922		754		1,168
Natural gas distribution	35	689		176		513		600		145		455
Total		$	4,559	$	1,944	$	2,615	$	4,153	$	1,754	$	2,399

(b) Depreciation and Amortization

The following table presents depreciation and amortization expense:


	Year Ended December 31,
	2021		2020
	(in millions)
Depreciation	$	133	$	127
Amortization of regulatory assets	2		2

Total	$	135	$	129

The Company recorded AROs relating to the closure of the ash ponds at A.B. Brown and F.B. Culley and to treated wood poles for electric distribution, distribution transformers containing PCB (also known as Polychlorinated Biphenyl), and underground fuel storage tanks. The Company also recorded AROs relating to gas pipelines abandoned in place. The estimates of future liabilities were developed using historical information, and where available, quoted prices from outside contractors.

A reconciliation of the changes in the ARO liability recorded in Other non-current liabilities in the Company’s Balance Sheets is as follows:


	December 31, 2021		December 31, 2020
	(in millions)
Beginning balance	$	94	$	92
Accretion expense (1)	4		1

Revisions in estimates (2)	26		1
Ending balance	$	124	$	94

(1)Reflected in non-current Regulatory assets on the Company’s Balance Sheets.

(2)In 2021, the Company reflected an increase in its ARO liability, which is primarily attributable to establishing an ARO for a new solar generation field, which went into service in 2021, and a revision to the ARO for Culley East ash pond for a new closure methodology and cash flows.

(5) Regulatory Assets & Liabilities

The following is a list of regulatory assets and liabilities reflected on the Company’s Balance Sheets as of December 31, 2021 and 2020.


	December 31,
	2021		2020
	(in millions)
Regulatory Assets:
Future amounts recoverable from ratepayers related to:
Asset retirement obligations & other	$	37	$	40
Net deferred income taxes	7		5

Total future amounts recoverable from ratepayers	44		45
Amounts deferred for future recovery related to:

Extraordinary gas costs (1)	11		—
Cost recovery riders	52		24
Gas recovery costs (1)	13		—
Total amounts deferred for future recovery	76		24
Amounts currently recovered through customer rates related to:
Authorized trackers and cost deferrals	89		91

Loss on reacquired debt and hedging costs	8		9



Total amounts recovered in customer rates	97		100
Total Regulatory Assets	$	217	$	169
Total Current Regulatory Assets	$	24	$	—
Total Non-current Regulatory Assets	$	193	$	169
Regulatory Liabilities:
Regulatory liabilities related to TCJA	$	182	$	184
Estimated removal costs	81		76
Other regulatory liabilities	21		—
Total Regulatory Liabilities	$	284	$	260

(1)Included in current regulatory assets on the Company’s Balance Sheets.

Of the $97 million currently being recovered in rates charged to customers, no amounts are earning a return. The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $43 million, is 16 years. Regulatory assets not earning a return with perpetual or undeterminable lives have been excluded from the weighted average recovery period calculation. The remainder of the regulatory assets are being recovered timely through periodic recovery mechanisms. The Company has rate orders for all deferred costs not yet in rates and therefore believes future recovery is probable.

Regulatory assets for asset retirement obligations, see Notes 4 and 10 for further information, are primarily a result of costs incurred for expected retirement activity for the Company's ash ponds beyond what has been recovered in rates. The Company believes the recovery of these assets are probable as the costs are currently being recovered in rates.

The deferred tax related regulatory liability is primarily the revaluation of deferred taxes at the reduced federal corporate tax rate that was enacted on December 22, 2017. These regulatory liabilities are being refunded to customers over time following regulatory commission approval.

February 2021 Winter Storm Event

In February 2021, the Company experienced an extreme and unprecedented winter weather event that resulted in prolonged freezing temperatures, which impacted its business. The February 2021 Winter Storm Event impacted wholesale prices of the Company’s natural gas purchases and its ability to serve customers in its service territory, including due to the reduction in available natural gas capacity and impacts to the Company’s natural gas supply portfolio activities, and the effects of weather on

their systems and their ability to transport natural gas, among other things. The overall natural gas market, including the markets from which the Company sourced a significant portion of their natural gas for their operations, experienced significant impacts caused by the February 2021 Winter Storm Event, resulting in extraordinary increases in the price of natural gas purchased by the Company.

The Company deferred under-recovered natural gas cost as regulatory assets under existing recovery mechanisms. As of December 31, 2021, the Company has recorded current regulatory assets of $11 million associated with the February 2021 Winter Storm Event through the gas cost recovery mechanism.

Amounts for the under recovery of natural gas costs are reflected in regulatory assets on the Company’s Balance Sheets. Recovery of natural gas costs within the regulatory assets are probable and are subject to customary regulatory prudence reviews in all jurisdictions that may impact the amounts ultimately recovered. The Company has begun recovery of natural gas costs attributable to the February 2021 Winter Storm Event.

COVID-19 Regulatory Matters

Governors, public utility commissions and other authorities in Indiana have issued a number of different orders related to the COVID-19 pandemic, including orders addressing customer non-payment and disconnection. Although the disconnect moratoriums have expired in the Company’s service territory, it continues to support those customers who may need payment assistance, arrangements or extensions.

The IURC has either (1) issued orders to record a regulatory asset for incremental bad debt expenses related to COVID-19, including costs associated with the suspension of disconnections and payment plans or (2) provided authority to recover bad debt expense through an existing tracking mechanism. The IURC issued an order in October 2021 for CEI South approving the settlement in its recent base rate case which included recovery of the applicable regulatory asset. The Company has recorded estimated incremental uncollectible receivables to the associated regulatory asset of $1 million, as of both December 31, 2021 and 2020.

The IURC has authorized utilities to employ deferred accounting authority for certain COVID-19 related costs which ensure the safety and health of customers, employees, and contractors, that would not have been incurred in the normal course of business.

(6) Transactions with Other Vectren Companies & Affiliates

Vectren Infrastructure Services Corporation (VISCO)

On April 9, 2020, Vectren closed on a transaction to sell its Infrastructure Services businesses which provided underground pipeline construction and repair services. VISCO's customers included the Company's utilities and fees incurred by the Company totaled:


		Year Ended December 31, 2020 (1)
	(in millions)
Pipeline construction and repair services(2)		$	6

(1)Represents charges for the period, January 1, 2020 until the closing of the sale of VISCO

(2)Amounts owed to VISCO are included in Accounts payable - affiliated companies.

Support Services and Purchases

Affiliates of CenterPoint Energy provide corporate and general and administrative services to the Company and allocate certain costs to the Company. These services are billed to the Company at actual cost, either directly or as allocation using various allocators, including number of employees, number of customers and/or the level of payroll, revenue contribution and capital expenditures. Affiliates of CenterPoint Energy provide other miscellaneous services, including geographic services and other management support. These services are billed at actual cost, and the charges are not necessarily indicative of what would have been incurred had CenterPoint Energy's subsidiaries not been affiliates. Amounts owed for support services and purchases at December 31, 2021 and 2020 are included in Accounts payable - affiliated companies.

Additionally, CenterPoint Energy, through an energy service subsidiary divested in June 2020, sold natural gas to the Company's Electric reportable segment for use in electric generation activities. Contracts for natural gas were executed in a competitive bidding process and are reflective of what would have been incurred had CenterPoint Energy not been an affiliate.


	Year Ended December 31,
	2021		2020(1)
	(in millions)
Affiliate natural gas expense (1)	$	—	$	1
Corporate allocations	53		55

(1)Amounts charged for natural gas are included primarily in Utility natural gas until the closing of the sale of CenterPoint Energy's energy service subsidiary.

Property, Plant and Equipment

In 2021, the Company purchased certain property, plant and equipment assets from VUHI at their net carrying value of $61 million on the date of purchase.

Retirement Plans & Other Postretirement Benefits

As of December 31, 2021, Vectren maintains three closed qualified defined benefit pension plans (Vectren Corporation Non-Bargaining Retirement Plan, The Indiana Gas Company, Inc. Bargaining Unit Retirement Plan, Pension Plan for Hourly Employees of Southern Indiana Gas and Electric Company), a nonqualified supplemental executive retirement plan (SERP), and a postretirement benefit plan. The defined benefit pension plans and postretirement benefit plan, which cover the Company’s eligible full-time regular employees, are primarily noncontributory. The postretirement benefit plan includes health care and life insurance benefits which are a combination of self-insured and fully insured programs. Vectren’s current and former employees comprise the vast majority of the participants and retirees covered by these plans. Effective in 2021, certain participants of the Vectren Non-Bargaining Retirement Plan and all liabilities and assets associated with the accrued benefits of such participants were transferred to and became participants of the CenterPoint Energy pension plan.

Vectren satisfies the future funding requirements for its funded plans and the payment of benefits for unfunded plans from general corporate assets and, as necessary, relies on the Company to support the funding of these obligations. However, the Company has no contractual funding obligation to the plans. The Company did not make a contribution in 2021 and 2020 to the Company's parents' defined benefit and pension plans. The Company contributed $1 million in 2021 and $2 million in 2020 to Vectren's SERP and post retirement benefit plans. The combined funded status of Vectren’s benefit pension plans was approximately 100 percent and 92 percent as of December 31, 2021 and 2020, respectively. The combined funded status of CenterPoint Energy's, excluding Vectren, defined pension plans was approximately 92 percent as of December 31, 2021.

Vectren allocates retirement plan and other postretirement benefit plan periodic cost calculated pursuant to GAAP to its subsidiaries, which is also how the Company recovers retirement plan periodic costs through base rates. Periodic cost is charged to the Company following a labor cost allocation methodology and results in retirement costs being allocated to both operating expense and capital projects. For the years ended December 31, 2021 and 2020, costs totaling $3 million and $4 million, respectively, were charged to the Company from CenterPoint Energy.

Any difference between the Company's funding requirements to Vectren and allocated periodic costs is recognized by the Company as an intercompany asset or liability. The allocation methodology to determine the intercompany funding requirements from the subsidiaries to Vectren is consistent with FASB guidance related to "multiemployer" benefit accounting. Neither plan assets nor plan obligations as calculated pursuant to GAAP by Vectren are allocated to individual subsidiaries.

As of December 31, 2021 and 2020, the Company had $22 million and $21 million, respectively, representing defined benefit pension funding by the Company to Vectren that is yet to be reflected in costs. As of December 31, 2021 and 2020, the Company had $18 million and $17 million, respectively, included in Other non-current liabilities representing costs related to other postretirement benefits charged to the Company that is yet to be funded to Vectren. The Company's labor allocation methodology is used to compute the Company's funding of the defined benefit retirement and other postretirement plans to Vectren, which is consistent with the regulatory ratemaking processes of the Company.

Share-Based Incentive Plans and Deferred Compensation Plans

The Company does not have share-based compensation plans separate from Vectren or CenterPoint Energy. As of December 31, 2021 most active employees of the deferred compensation plans were transferred out of VUHI and into other CenterPoint Energy companies. As of December 31, 2021 and 2020, less than $1 million and $3 million, respectively, is included in Other non-current liabilities and represents deferred compensation obligations that are yet to be funded in CenterPoint Energy's plan.

Cash Management Arrangements

The Company participates in the centralized cash management program with affiliates of Vectren. See Note 7 for further information regarding intercompany borrowing arrangements.

Guarantees of the Company's Parent

The three operating utility companies of VUHI, the Company, CEI North and CEOH are guarantors of its credit facility, its $350 million commercial paper borrowing arrangements and its $377 million in unsecured senior notes outstanding at December 31, 2021. The majority of VUHI's unsecured senior notes outstanding are allocated to the operating utility companies. The guarantees are full and unconditional and joint and several, and VUHI has no subsidiaries other than the subsidiary guarantors.

Income Taxes

The Company does not file federal or state income tax returns separate from those filed by Vectren or CenterPoint Energy. As of February 2, 2019, Vectren is included in CenterPoint Energy's consolidated U.S. federal income tax return. Vectren and/or certain of its subsidiaries file income tax returns in various states. Pursuant to a tax sharing agreement and for financial reporting purposes, Vectren subsidiaries record income taxes on a separate company basis. The Company's allocated share of tax effects resulting from it being a part of Vectren's consolidated tax group are recorded at the Company's parent level. Current taxes payable/receivable are settled with Vectren in cash quarterly and after filing the consolidated federal and state income tax returns.

Deferred income taxes are provided for temporary differences between the tax basis (adjusted for related unrecognized tax benefits, if any) of an asset or liability and its reported amount in the financial statements. Deferred tax assets and liabilities are computed based on the currently-enacted statutory income tax rates that are expected to be applicable when the temporary differences are scheduled to reverse. The Company recognizes regulatory liabilities for deferred taxes provided in excess of the current statutory tax rate and regulatory assets for deferred taxes provided at rates less than the current statutory tax rate. Such tax-related regulatory assets and liabilities are reported at the revenue requirement level and amortized to income as the related temporary differences reverse, generally over the lives of the related properties. A valuation allowance is recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that the deferred tax assets will be realized.

Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the more-likely-than-not recognition threshold is satisfied and measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company reports interest and penalties associated with unrecognized tax benefits within Income taxes in the Statements of Income and reports tax liabilities related to unrecognized tax benefits as part of Other non-current liabilities.

Investment tax credits (ITCs) are deferred and amortized to income over the approximate lives of the related property. Production tax credits (PTCs) are recognized as energy is generated and sold based on a per kilowatt hour rate prescribed in applicable federal and state statutes.

The Company's gas and electric utilities currently recover corporate income tax expense in approved rates charged to customers. The IURC issued an order which initiated a proceeding to investigate the impact of the Tax Cuts and Jobs Act (TCJA) on utility companies and customers within the state. In addition, the IURC ordered the Company to establish regulatory liabilities to record all estimated impacts of tax reform starting January 1, 2018. For further information, see Note 5.

The components of income tax expense/(benefit) and amortization of investment tax credits follow:


	Year Ended December 31,
	2021		2020
	(in millions)
Current:
Federal	$	—	$	(19)
State	2		(4)
Total current tax expense/(benefit)	2		(23)
Deferred:
Federal	(11)		34
State	5		10
Total deferred tax expense	(6)		44
Investment tax credit amortization	(1)		(1)
Investment tax credit deferred	26		—
Total income tax expense	$	21	$	20

A reconciliation of the federal statutory rate to the effective income tax rate follows:


	Year Ended December 31,
	2021		2020
Statutory rate	21	%	21	%

State & local taxes, net of federal benefit	4		4
Amortization of investment tax credit	(1)		—
Research & development tax credits	(1)		—
Regulatory liability amortization settled through rates	(4)		(4)

All other - net	(2)		(2)
Effective tax rate	17	%	19	%

Significant components of the net deferred tax liability follow:


	December 31,
	2021		2020
	(in millions)
Non-current deferred tax assets:
Net operating loss & other carryforwards	$	26	$	—
Regulatory liabilities settled through future rates	43		43
Total deferred tax assets	69		43
Non-current deferred tax liabilities:
Depreciation & cost recovery timing differences	299		284
Regulatory assets recoverable through future rates	7		7

Employee benefit obligations	2		2
Deferred fuel costs	14		9
Other – net	8		8
Total deferred tax liabilities	330		310
Net deferred tax liability	$	261	$	267

As of December 31, 2021, the Company has $26 million investment tax credit carryforward that will expire in 2041. As of December 31, 2021 and 2020, investment tax credits totaling $28 million and $3 million, respectively, are included in Other non-current liabilities, respectively.

Uncertain Tax Positions

Unrecognized tax benefits for all periods presented were not material to the Company. The net liability on the Balance Sheet for unrecognized tax benefits inclusive of interest and penalties totaled less than $1 million as of both December 31, 2021 and 2020.

The Company's parent and certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. The Internal Revenue Service (IRS) is currently auditing Vectren's U.S. federal income 2014-2019 tax returns. The State of Indiana, Vectren's primary state tax jurisdiction, has concluded examinations of Vectren's consolidated state income tax returns for tax years through 2017 with no adjustments. The statutes of limitations for assessment of Indiana income tax have expired with respect to tax years through 2016 except to the extent of refunds claimed on amended tax returns. Tax years through 2018 have been audited and settled with the IRS for CenterPoint Energy. For the 2019-2021 tax years, CenterPoint Energy and its subsidiaries are participants in the IRS’s Compliance Assurance Process.

(7)Borrowing Arrangements & Other Financing Transactions

Long-Term Debt

Long-term senior unsecured obligations and first mortgage bonds outstanding follow:


	December 31,
	2021		2020
	(in millions)
Fixed Rate Senior Unsecured Notes Payable to Affiliated Companies
2021, 4.67%	$	—	$	55
2023, 3.72%	25		25
2025, 1.21%	106		—
2028, 3.20%	27		27
2030, 1.72%.	75		56
2032, 3.26%	75		75
2035, 6.10%	25		25
2035, 3.90%	17		17
2043, 4.25%	48		48
2045, 4.36%	16		16
2047, 3.93%	30		30
2049, 3.42%	80		80
2050, 3.920%	100		100
2055, 4.51%	16		16


Total long-term debt payable - affiliated companies	640		570
Current maturities	—		(55)
Total long-term debt payable - affiliated companies, net of current maturities	$	640	$	515


	December 31,
	2021		2020
	(in millions)
First Mortgage Bonds Payable to Third Parties:
2022, 2013 Series C, current adjustable rate .83%, tax-exempt	$	5	$	5
2024, 2013 Series D, current adjustable rate .83%, tax-exempt	23		23
2025, 2014 Series B, current adjustable rate .83%, tax-exempt	41		41
2029, 1999 Series, 6.72%	80		80
2037, 2013 Series E, current adjustable rate .83%, tax-exempt	22		22
2038, 2013 Series A, current adjustable rate .83%, tax-exempt	22		22
2043, 2013 Series B, current adjustable rate .83%, tax-exempt	40		40
2044, 2014 Series A, 4.00%, tax exempt	22		22
2055, 2015 Series Mt. Vernon, .875%, tax-exempt	15		23
2055, 2015 Series Warrick County, .875%, tax-exempt	23		15
Total first mortgage bonds payable to third parties	293		293
Current maturities	(5)		—


Total long-term debt payable to third parties, net of current maturities	$	288	$	293

Mandatory Tenders. Certain series of the Company's bonds, originally aggregating $186 million, are subject to mandatory tenders prior to the bond's final maturities. In 2020, $38 million of such bonds was tendered and remarketed and $148 million of such bonds are subject to being tendered in 2023.

Future Long-Term Debt Sinking Fund Requirements and Maturities. As of December 31, 2021, the Company had approximately $293 million aggregate principal amount of first mortgage bonds outstanding. Generally, all of the Company’s real and tangible property is subject to the lien of its mortgage indenture. The Company may issue additional bonds under its mortgage indenture up to 60% of currently unfunded property additions. As of December 31, 2021, approximately $1.4 billion of additional first mortgage bonds could be issued on this basis. However, the Company is also limited in its ability to issue additional bonds under its mortgage indenture due to certain provisions in its parent’s, VUHI, debt agreements.

Maturities. As of December 31, 2021, maturities of long-term debt were as follows:


	Affiliate Debt		Third Party Debt		Total Debt
	(in millions)
2022	$	—	$	5	$	5
2023	25		—		25
2024	—		23		23
2025	106		41		147
2026	—		—		—
2027 and thereafter	509		224		733

Covenants. Long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage, among other restrictions. As of December 31, 2021, the Company was in compliance with all financial debt covenants.

(8)Commitments & Contingencies

(a) Purchase Obligations

Commitments include minimum purchase obligations related to the Company's Natural Gas reportable segment and Electric reportable segment. A purchase obligation is defined as an agreement to purchase goods or services that is enforceable and legally binding on the Company and that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Contracts with minimum payment provisions have various quantity requirements and durations and are not classified as non-trading derivative assets and liabilities in the

Company's Balance Sheets as of December 31, 2021 and 2020. These contracts meet an exception as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas and coal supply commitments also include transportation contracts that do not meet the definition of a derivative.

On February 9, 2021, CEI South entered into a BTA with a subsidiary of Capital Dynamics. Pursuant to the BTA, Capital Dynamics, with its partner Tenaska, will build a 300 MW solar array in Posey County, Indiana through a special purpose entity, Posey Solar. Upon completion of construction, currently projected to be at the end of 2023, and subject to IURC approval, which was received on October 27, 2021, CEI South will acquire Posey Solar and its solar array assets for a fixed purchase price. Due to rising costs for the project, caused in part by supply chain disruptions and the rising cost of commodities, Capital Dynamics is planning to downsize the project to approximately 200 MWs to remain viable. CEI South collaboratively agreed to the scope change and is currently working through contract negotiations, contingent on further IURC review and approval.

As of December 31, 2021, minimum purchase obligations were approximately:


	Natural Gas and Coal Supply		Other (1)
	(in millions)
2022	$	116	$	53
2023	77		490
2024	43		70
2025	42		30
2026	36		30
2027 and beyond	152		165

(1)The Company’s undiscounted minimum payment obligations related to PPAs with commitments ranging from 15 to 25 years and its purchase commitment under its BTA in Posey County, Indiana at the original contracted amount, prior to any renegotiation, are included above. The remaining undiscounted payment obligations relate primarily to technology hardware and software agreements.

Excluded from the table above are estimates for cash outlays from other PPAs through CEI South that do not have minimum thresholds but do require payment when energy is generated by the provider. Costs arising from certain of these commitments are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms

(b) AMAs

The Company entered into a third-party AMA beginning in April 2021 through March 2024 associated with its utility distribution service in Indiana. Pursuant to the provisions of the agreement, the Company either sells natural gas to the asset manager and agrees to repurchase an equivalent amount of natural gas throughout the year at the same cost, or simply purchases its full natural gas requirements at each delivery point from the asset manager. Generally, AMAs are contracts between the Company and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these agreements, the Company agrees to release transportation and storage capacity to other parties to manage natural gas storage, supply and delivery arrangements for the Company and to use the released capacity for other purposes when it is not needed for the Company. The Company may receive compensation from the asset manager through payments made over the life of the AMAs. The Company has an obligation to purchase their winter storage requirements that have been released to the asset manager under these AMAs.

MGP Sites. The Company and its predecessors operated MGPs in the past. The Company has accrued estimated costs for investigation, remediation, and ground water monitoring that it expects to incur to fulfill its respective obligations using assumptions based on actual costs incurred, the timing of expected future payments and inflation factors, among others. While the Company has recorded all costs which it presently is obligated to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen, and those costs may not be subject to PRP or insurance recovery.

Indiana MGPs. The Company has also identified its involvement in 5 manufactured gas plant sites in the Company's service territory, all of which are currently enrolled in the IDEM’s VRP. The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites.

Total costs that may be incurred in connection with addressing these sites cannot be determined at this time. The estimated accrued costs are limited to the Company's share of the remediation efforts and are therefore net of exposures of other PRPs. The estimated range of possible remediation costs for the sites for which the Company believes it may have responsibility was based on remediation continuing for the minimum time frame given in the table below.


	December 31, 2021
	(in millions, except years)
Amount accrued for remediation	$	2
Minimum estimated remediation costs	1
Maximum estimated remediation costs	8
Minimum years of remediation	5
Maximum years of remediation	10

The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will depend on the number of sites to be remediated, the participation of other PRPs, if any, and the remediation methods used.

The Company does not expect the ultimate outcome of these matters to have a material adverse effect on the financial condition, results of operations or cash flows.

CCR Rule. In April 2015, the EPA finalized its CCR Rule, which regulates ash as non-hazardous material under the RCRA. The final rule allows beneficial reuse of ash, and the majority of the ash generated by CEI South’s generating plants will continue to be reused. In July 2018, the EPA released its final CCR Rule Phase I Reconsideration which extended the deadline to October 31, 2020 for ceasing placement of ash in ponds that exceed groundwater protections standards or that fail to meet location restrictions. In August 2019, the EPA proposed additional “Part A” amendments to its CCR Rule with respect to beneficial reuse of ash and other materials. Further “Part B” amendments, which related to alternate liners for CCR surface impoundments and the surface impoundment closure process, were published in March 2020. The Part A amendments were finalized in August 2020 and extended the deadline to cease placement of ash in ponds to April 11, 2021, discussed further below. The EPA published the final Part B amendments in November 2020. The Part A amendments do not restrict the Company's current beneficial reuse of its fly ash. The Company evaluated the Part B amendments to determine potential impacts and determined that the Part B amendments did not have an impact on its current plans. Shortly after taking office in January 2021, President Biden signed an executive order requiring agencies to review environmental actions taken by the Trump administration, including the CCR Rule Phase I Reconsideration, the Part A amendments, and the Part B amendments; the EPA has completed its review of the Phase I Reconsideration, Part A amendments, and Part B amendments and determined that the most environmentally protective course is to implement the rules.

CEI South has three ash ponds, two at the F.B. Culley facility (Culley East and Culley West) and one at the A.B. Brown facility. Under the existing CCR Rule, CEI South is required to perform integrity assessments, including ground water monitoring, at its F.B. Culley and A.B. Brown generating stations. The ground water studies are necessary to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place. CEI South’s Warrick generating unit is not included in the scope of the CCR Rule as this unit has historically been part of a larger generating station that predominantly serves an adjacent industrial facility. Preliminary groundwater monitoring indicates potential groundwater impacts very close to CEI South’s ash impoundments, and further analysis is ongoing. The CCR Rule required companies to complete location restriction determinations by October 18, 2018. The Company completed its evaluation and determined that one F.B. Culley pond (Culley East) and the A.B. Brown pond fail the aquifer placement location restriction. As a result of this failure, CEI South was required to cease disposal of new ash in the ponds and commence closure of the ponds by April 11, 2021, unless approved for an extension. CenterPoint Energy has applied for the extensions available under the CCR Rule that would allow CEI South to continue to use the ponds through October 15, 2023. The EPA is still reviewing industry extension requests, including the Company’s extension request. Companies can continue to operate ponds pending completion of the EPA’s evaluation of the requests for extension. If the EPA denies a full extension request, that denial may result in increased and potentially significant operational costs in connection with the accelerated implementation of an alternative ash disposal system or may adversely impact CEI South’s future operations. Failure to comply with a cease waste receipt could also result in an enforcement proceeding, resulting in the imposition of fines and penalties. On April 24, 2019, CEI South received an order from the IURC approving

recovery in rates of costs associated with the closure of the Culley West pond, which has already completed closure activities. On August 14, 2019, CEI South filed its petition with the IURC for recovery of costs associated with the closure of the A.B. Brown ash pond, which would include costs associated with the excavation and recycling of ponded ash. This petition was subsequently approved by the IURC on May 13, 2020. On October 28, 2020, the IURC approved CEI South’s ECA proceeding, which included the initiation of recovery of the federally mandated project costs.

CEI South continues to refine site specific estimates of closure costs for its ten-acre Culley East pond. In July 2018, CEI South filed a Complaint for Damages and Declaratory Relief against its insurers seeking reimbursement of defense, investigation and pond closure costs incurred to comply with the CCR Rule, and has since reached confidential settlement agreements with its insurers. The proceeds of these settlements will offset costs that have been and will be incurred to close the ponds.

As of December 31, 2021, the Company has recorded an approximate $90 million ARO, which represents the discounted value of future cash flow estimates to close the ponds at A.B. Brown and F.B. Culley. This estimate is subject to change due to the contractual arrangements; continued assessments of the ash, closure methods, and the timing of closure; implications of CEI South’s generation transition plan; changing environmental regulations; and proceeds received from the settlements in the aforementioned insurance proceeding. In addition to these removal costs, CEI South also anticipates equipment purchases of between $60 million and $80 million to complete the A.B. Brown closure project.

Clean Water Act Permitting of Groundwater Discharges. In April 2021, the U.S. Supreme Court issued an opinion providing that indirect discharges via groundwater or other non-point sources are subject to permitting and liability under the Clean Water Act when they are the functional equivalent of a direct discharge. The Company is evaluating the extent to which this decision will affect Clean Water Act permitting requirements and/or liability for their operations.

Other Environmental. From time to time, the Company identifies the presence of environmental contaminants during operations or on property where predecessors have conducted operations. Other such sites involving contaminants may be identified in the future. The Company has and expects to continue to remediate any identified sites consistent with state and federal legal obligations. From time to time, the Company has received notices, and may receive notices in the future, from regulatory authorities or others regarding status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been, or may be, named from time to time as defendants in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, the Company does not expect these matters, either individually or in the aggregate, to have a material adverse effect on their financial condition, results of operations or cash flows.

Other Proceedings

The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. From time to time, the Company is also defendant in legal proceedings with respect to claims brought by various plaintiffs against broad groups of participants in the energy industry. Some of these proceedings involve substantial amounts. The Company regularly analyzes current information and, as necessary, provides accruals for probable and reasonably estimable liabilities on the eventual disposition of these matters. The Company does not expect the disposition of these matters to have a material adverse effect on the Company's financial condition, results of operations or cash flows.

(9)Regulatory Matters

COVID-19 Regulatory Matters

For information about COVID-19 regulatory matters, see Note 5 to the financial statements.

February 2021 Winter Storm Event

The table below presents the incremental natural gas costs included in regulatory assets as of December 31, 2021 as a result of the February 2021 Winter Storm Event and the Company's requested recovery status as of March 2022.

State

Recovery Status

Legislative Activity

Incremental Gas Cost in Regulatory Assets (in millions)


CEI South	IURC issued order July 28, 2021. Recovery began August 2021 with 50% of the February 2021 variance recovered evenly over the 12‐month period August 2021 to July 2022, with the remainder of the variance recovered through a volumetric per‐therm allocation over the same 12-month period.	None.	11
		Total	$	11

CEI South CPCN

On February 9, 2021, CEI South entered into a BTA with a subsidiary of Capital Dynamics. Under the agreement, Capital Dynamics, with its partner Tenaska, contracted to build a 300 MW solar array in Posey County, Indiana through a special purpose entity, Posey Solar. Upon completion of construction, which is projected to be at the end of 2023, CEI South will acquire Posey Solar and its solar array assets for a fixed purchase price. On February 23, 2021, CEI South filed a CPCN with the IURC seeking approval to purchase the project. CEI South also sought approval for a 100 MW solar PPA with Clenera LLC in Warrick County, Indiana. The request accounted for increased cost of debt related to this PPA, which provides equivalent equity return to offset imputed debt during the 25 year life of the PPA. A hearing was conducted on June 21, 2021. On October 27, 2021, the IURC issued an order approving the CPCN, authorizing CEI South to purchase the Posey solar project through a BTA and approved recovery of costs via a levelized rate over the anticipated 35-year life. The IURC also approved the Warrick County solar PPA but denied the request to preemptively offset imputed debt in the PPA cost. The Posey solar project is expected to be in service by 2023. Due to rising costs for the project, caused in part by supply chain issues in the energy industry and the rising costs of commodities, we, along with Capital Dynamics, recently announced plans to downsize the project to approximately 200 MW. CEI South collaboratively agreed to the scope change and is currently working through contract negotiations, contingent on further IURC review and approval.

On June 17, 2021 CEI South filed a CPCN with the IURC seeking approval to construct two natural gas combustion turbines to replace portions of its existing coal-fired generation fleet. CEI South has also requested depreciation expense and post in-service carrying costs to be deferred in a regulatory asset until the date Indiana South’s base rates include a return on and recovery of depreciation expense on the facility. A hearing was conducted on January 26 through 28, 2022. The estimated $334 million turbine facility would be constructed at the current site of the A.B. Brown power plant in Posey County, Indiana and would provide a combined output of 460 MW. Construction of the turbines will begin following receipt of necessary regulatory approvals by the IURC and FERC, which are anticipated in the second half of 2022 and first quarter 2023, respectively. The turbines are targeted to be operational in first quarter of 2025. Subject to IURC approval, recovery of the proposed natural gas combustion turbines and regulatory asset will be requested in the next CEI South rate case expected in 2023.

On August 25, 2021, CEI South filed with the IURC seeking approval to purchase 185 MW of solar power, under a 15-year PPA, from Oriden LLC, which is developing a solar project in Vermillion County, Indiana, and 150 MW of solar power, under a 20-year PPA, from Origis Energy USA Inc., which is developing a solar project in Knox County, Indiana. Subject to necessary approvals, both solar arrays are expected to be in service by 2023.

CEI South Securitization of Planned Generation Retirements

The State of Indiana has enacted legislation, Senate Bill 386, that would enable the Company to request approval from the IURC to securitize the remaining book value and removal costs associated with generating facilities to be retired in the next twenty-four months. The Governor of Indiana signed the legislation on April 19, 2021. The Company intends to seek securitization in the future associated with planned retirements of coal generation facilities in 2022.

Subsidiary Restructuring

In July 2021, CEI North and CEI South filed petitions with the IURC for the approval of a new financial services agreement and the confirmation of CEI North’s financing authority, and final orders were issued by the IURC on December 28, 2021. CEOH filed a similar application with the PUCO in September 2021 and the PUCO issued an order on January 26, 2022 adopting recommendations by PUCO staff. CenterPoint Energy is evaluating the transfer of CEI North and CEOH from VUHI to CERC in order to better align its organizational structure with management and financial reporting. Both the IURC and PUCO have approved the transaction. As a part of the restructuring, VUHI may approach certain of its debt holders with an offer to exchange existing VUHI debt for CERC debt. The orders allow the reissuance of existing debt of CEI North and CEOH to CERC, to continue to amortize existing issuance expenses and discounts, and to treat any potential exchange fees as discounts to be

amortized over the life of the debt. If CenterPoint Energy moves forward with the restructuring, including any VUHI debt exchanges, it is expected to be completed in 2022.

CEI South Base Rate Case

On October 30, 2020, and as subsequently amended, CEI South filed its base rate case with the IURC seeking approval for a revenue increase of approximately $29 million. This rate case filing is required under Indiana TDSIC statutory requirements before the completion of Indiana South’s capital expenditure program, approved in 2014 for investments starting in 2014 through 2020. The revenue increase is based upon a requested ROE of 10.15% and an overall after-tax rate of return of 5.99% on total rate base of approximately $469 million. Indiana South has utilized a projected test year, reflecting its 2021 budget as the basis for the revenue increase requested and proposes to implement rates in two phases. On April 23, 2021, a Stipulation and Settlement Agreement was filed resolving all issues in the case. The settlement recommended a revenue increase of $21 million based on a 9.7% ROE and an overall after-tax rate of return of 5.78% on total rate base of approximately $469 million. A settlement hearing was held on June 24, 2021. On October 6, 2021, the IURC issued an order approving the settlement. Phase one rates, reflecting actual plant-in-service and cost of capital through June 2021, became effective in October 2021 and phase two rates, reflecting actual plant-in-service and cost of capital through December 2021 with certain adjustments, will become effective in March 2022.

Rate Change Applications

The Company is routinely involved in rate change applications before state regulatory authorities. Those applications include general rate cases, where the entire cost of service of the utility is assessed and reset. In addition, the Company is periodically involved in proceedings to adjust its capital tracking mechanisms in Indiana (CSIA for gas and TDSIC, ECA and CECA for Electric). The table below reflects significant applications pending or completed since the Company’s 2020 financial statements were furnished to the SEC on Current Report 8-K dated March 26, 2021.

Mechanism

Annual Increase (Decrease) (1) (in millions)

Filing Date

Effective Date

Approval Date

Additional Information

CEI South - Gas (IURC)

CSIA

(1)

April
2021

July
2021

Represents an increase of $11 million to rate base (investment period July 2020 through December 2020), which reflects a $(1 million) annual decrease in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case, which was filed in December 2020. The mechanism also includes refunds associated with the TCJA, resulting in no change to the previous credit provided, and a change in the total (over)/under-recovery variance of less than $1 million annually.

Rate Case

October 2020

October 2021

See discussion above under CEI South Base Rate Case.

Mechanism

Annual Increase (Decrease) (1) (in millions)

Filing Date

Effective Date

Approval Date

Additional Information

CEI South - Electric (IURC)

TDSIC (1)

February 2022

TBD

Requested an increase of $42 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of less than $1 million.

CECA (1)

(2)

February 2022

TBD

Requested a decrease of less than $1 million to rate base, which reflects a $3 million annual decrease in current revenues. The mechanism also includes a change in (over)/under-recovery variance of less than $1 million. This mechanism includes a non-traditional rate making approach related to a 50 MW universal solar array placed in service in January 2021.

TDSIC

August 2021

November 2021

Requested an increase of $35 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of less than $1 million.

ECA

May
2021

September 2021

Requested an increase of $39 million to rate base, which reflects a $2 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also included a change in (over)/under-recovery variance of less than $1 million annually.

TDSIC

February 2021

May
2021

Requested an increase of $28 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of less than $1 million.

CECA

February 2021

June
2021

May
2021

Reflects an $8 million annual increase in current revenues through a non-traditional rate making approach related to a 50 MW universal solar array placed in service in January 2021.

(1)Represents proposed increases (decreases) when effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates.

(10) Environmental and Sustainability Matters

Global Climate Change

There is increasing attention being paid in the United States and worldwide to the issue of climate change. As a result, from time to time, regulatory agencies have considered the modification of existing laws or regulations or the adoption of new laws or regulations addressing the emissions of GHG on the state, federal, or international level. On August 3, 2015, the EPA released its CPP rule, which required a 32% reduction in carbon emissions from 2005 levels. The final rule was published in the Federal Register on October 23, 2015, and that action was immediately followed by litigation ultimately resulting in the U.S. Supreme Court staying implementation of the rule. On July 8, 2019, the EPA published the ACE rule, which (i) repealed the CPP rule; (ii) replaced the CPP rule with a program that requires states to implement a program of energy efficiency improvement targets for individual coal-fired electric generating units; and (iii) amended the implementing regulations for Section 111(d) of the Clean Air Act. On January 19, 2021, the majority of the ACE rule — including the CPP repeal, CPP replacement, and the timing-related portions of the Section 111(d) implementing rule — was struck down by the U.S. Court of Appeals for the D.C. Circuit and on

October 29, 2021, the U.S. Supreme Court agreed to consider four petitions filed by various coal interests and a coalition of 19 states that seek review of the lower court’s decision vacating the ACE rule. The Company is currently unable to predict what a replacement rule for either the ACE rule or CPP would require.

The Biden administration recommitted the United States to the Paris Agreement, which can be expected to drive a renewed regulatory push to require further GHG emission reductions from the energy sector and proceeded to lead negotiations at the global climate conference in Glasgow, Scotland. On April 22, 2021, President Biden announced new goals of 50% reduction of economy-wide GHG emissions, and 100% carbon-free electricity by 2035, which formed the basis of the United States' commitments announced in Glasgow. In September 2021, CenterPoint Energy announced its new net zero emissions goals for both Scope 1 and Scope 2 emissions by 2035 as well as a goal to reduce Scope 3 emissions by 20% to 30% by 2035. The Company’s revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of its operations or would have the effect of reducing the consumption of natural gas. In addition, the EPA has indicated that it intends to implement new regulations targeting reductions in methane emissions, which are likely to increase costs related to production, transmission and storage of natural gas. Incentives to conserve energy or to use energy sources other than natural gas could result in a decrease in demand for the Company’s services. Further, certain local government bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by certain specified dates. These initiatives could have a significant impact on the Company and its operations, and this impact could increase if other cities and jurisdictions in its service area enact similar initiatives. Further, our third party suppliers, vendors and partners may also be impacted by climate change laws and regulations, which could impact the Company’s business by, among other things, causing permitting and construction delays, project cancellations or increased project costs passed on to the Company. Conversely, regulatory actions that effectively promote the consumption of natural gas because of its lower emissions characteristics would be expected to benefit the Company. At this time, however, the Company cannot quantify the magnitude of the impacts from possible new regulatory actions related to GHG emissions, either positive or negative, on the Company’s business.

Climate Change Trends and Uncertainties

As a result of increased awareness regarding climate change, coupled with adverse economic conditions, availability of alternative energy sources, including private solar, microturbines, fuel cells, energy-efficient buildings and energy storage devices, and new regulations restricting emissions, including potential regulations of methane emissions, some consumers and companies may use less energy, meet their own energy needs through alternative energy sources or avoid expansions of their facilities, including natural gas facilities, resulting in less demand for the Company's services. As these technologies become a more cost-competitive option over time, whether through cost effectiveness or government incentives and subsidies, certain customers may choose to meet their own energy needs and subsequently decrease usage of the Company's systems and services, which may result in, among other things, CEI South's generating facilities becoming less competitive and economical. Further, evolving investor sentiment related to the use of fossil fuels and initiatives to restrict continued production of fossil fuels have had significant impacts on the Company's electric generation and natural gas businesses. For example, because CEI South’s current generating facilities substantially rely on coal for their operations, certain financial institutions choose not to participate in the Company's financing arrangements. Conversely, demand for the Company's services may increase as a result of customer changes in response to climate change. For example, as the utilization of electric vehicles increases, demand for electricity may increase, resulting in increased usage of the Company's systems and services. Any negative opinions with respect to the Company's environmental practices or its ability to meet the challenges posed by climate change formed by regulators, customers, legislators or other stakeholders could harm its reputation.

To address these developments, CenterPoint Energy announced its new net zero emissions goals for both Scope 1 and Scope 2 emissions by 2035. In June of 2020, CEI South identified a preferred generation resource in its most recent IRP submitted to the IURC that aligns with its new net zero emission goals and includes the replacement of 730 MW of coal-fired generation facilities with a significant portion comprised of renewables, including solar and wind, supported by dispatchable natural gas combustion turbines, including a pipeline to serve such natural gas generation, as well as storage. The Company believes its planned investments in renewable energy generation and corresponding planned reduction in its GHG emissions as part of its newly adopted net zero emissions goals support global efforts to reduce the impacts of climate change.

To the extent climate changes result in warmer temperatures in the Company’s service territory, financial results from its business could be adversely impacted. For example, the Company could be adversely affected through lower natural gas sales. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes, tornadoes and flooding, including such storms as the February 2021 Winter Storm Event. To the extent adverse weather conditions affect the Company’s suppliers, results from their natural gas business may suffer. When the Company cannot deliver natural gas to customers, or customers cannot receive services, the Company’s financial results can be impacted by lost revenues, and it generally

must seek approval from regulators to recover restoration costs. To the extent the Company is unable to recover those costs, or if higher rates resulting from recovery of such costs result in reduced demand for services, the Company’s future financial results may be adversely impacted. Further, as the intensity and frequency of significant weather events continues, it may impact the Company’s ability to secure cost-efficient insurance.

Effluent Limitation Guidelines (ELG)

In 2015, the EPA finalized revisions to the existing steam electric wastewater discharge standards which set more stringent wastewater discharge limits and effectively prohibited further wet disposal of coal ash in ash ponds. These new standards are applied at the time of permit renewal and an affected facility must comply with the wastewater discharge limitations no later than December 31, 2023, and the prohibition of wet sluicing of bottom ash no later than December 31, 2025. In February 2019, the IURC approved CEI South’s ELG compliance plan for its F.B. Culley Generating Station, and CEI South is currently finalizing its ELG compliance plan for the remainder of its affected units as part of its ongoing IRP process.

Cooling Water Intake Structures

Section 316 of the federal Clean Water Act requires steam electric generating facilities use “best technology available” to minimize adverse environmental impacts on a body of water. In May 2014, the EPA finalized a regulation requiring installation of “best technology available” to mitigate impingement and entrainment of aquatic species in cooling water intake structures. CEI South is currently completing the required ecological studies and anticipates timely compliance in 2022-2023.

(11) Fair Value Measurements

Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings and cash & cash equivalents, those carrying amounts approximate fair value. Because of the inherent difficulty of estimating interest rate and other market risks, the methods used to estimate fair value may not always be indicative of actual realizable value, and different methodologies could produce different fair value estimates at the reporting date. The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:


	December 31,
	2021				2020
	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
	(in millions)
Long-term debt payable to third parties	$	293	$	316	$	293	$	324
Long-term debt payable - affiliated companies	640		686		570		654


Cash & cash equivalents	2		2		3		3
Natural gas purchase instrument assets (1)	2		2		—		—
Natural gas purchase instrument liabilities (2)	—		—		2		2
Interest rate swap liabilities (2) (3)	14		14		20		20

(1)Presented in Prepaid expenses and other current assets and Other non-current assets on the Balance Sheets.

(2)Presented in Accrued liabilities and Other non-current liabilities on the Balance Sheets.

(3)The interest rate swaps contain provisions that require the Company to maintain an investment grade credit rating on its long-term unsecured unsubordinated debt from S&P and Moody’s. If the Company’s debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the interest rate swaps could request immediate payment. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position on December 31, 2021, is approximately $14 million for which the Company has posted collateral of $7 million in the normal course of business. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2021, the Company would be required to post an additional $7 million of collateral to its counterparties. The maximum collateral required if further escalating collateral is triggered would equal the net liability position.

Under current regulatory treatment, call premiums on reacquisition of utility-related long-term debt are generally recovered in customer rates over the life of the refunding issue. Accordingly, any reacquisition of this debt would not be expected to have a material effect on the Company's results of operations.

The Company entered into two five-year forward purchase arrangements to hedge the variable price of natural gas for a portion of the Company’s gas supply. These arrangements, approved by the IURC, replaced normal purchase or normal sale long-term physical fixed-price purchases. The Company values these contracts using a pricing model that incorporates market-based information, and are classified within Level 2 of the fair value hierarchy. Gains and losses on these derivative contracts are deferred as regulatory liabilities or assets and are refunded to or collected from customers through the Company’s gas cost recovery mechanism.

(12) Segment Reporting

The Company’s determination of reportable segments considers the strategic operating units under which its CODM manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The Company's CODM views net income as the measure of profit or loss for the reportable segments.

As of December 31, 2021, reportable segments are as follows:

•The Natural Gas segment provides natural gas distribution and transportation services to primarily southwestern Indiana.

•The Electric segment provides electric generation, transmission and distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations.

Information related to the Company’s business segments is summarized below:


	Revenues from External Customers		Depreciation and Amortization		Net Income
	(in millions)
For the year ended December 31, 2021:
Natural Gas	$	134	$	19	$	15
Electric	629		116		91
Total	$	763	$	135	$	106
For the year ended December 31, 2020:
Natural Gas	$	100	$	16	$	9
Electric	554		104		73
Total	$	654	$	120	$	82


	Year Ended December 31,
	2021		2020
	(in millions)
Capital Expenditures
Natural Gas	$	73	$	48
Electric	254		260
Non-cash costs & changes in accruals	(18)		(9)
Total capital expenditures	$	309	$	299


	December 31,
	2021		2020
	(in millions)
Assets
Natural Gas	$	626	$	552
Electric	2,448		2,255

Total assets	$	3,074	$	2,807

(13)Additional Balance Sheet & Operational Information

Prepaid expenses and other current assets in the Balance Sheets consist of the following:


	December 31,
	2021		2020
	(in millions)
Prepaid taxes	$	16	$	—

Other	13		8
Total prepayments & other current assets	$	29	$	8

Accrued liabilities in the Balance Sheets consist of the following:


	December 31,
	2021		2020
	(in millions)
Accrued taxes	$	21	$	13

Refunds to customers & customer deposits	11		11
Accrued interest	5		5
Tax collections payable	—		1
Accrued salaries & other	14		7
Total accrued liabilities	$	51	$	37

Supplemental Cash Flow Information:


	Year Ended December 31,
	2021		2020
	(in millions)
Cash Payments/Receipts:
Income tax refunds	$	(6)	$	(31)
Interest	32		32
Non-cash transactions:
Accounts payable related to capital expenditures	$	14	$	8

(14) Impact of Recently Issued Accounting Standards

Management believes that other recently adopted standards and recently issued standards that are not yet effective will not have a material impact on the Company's financial position, results of operations or cash flows upon adoption.

(15) Leases

An arrangement is determined to be a lease at inception based on whether the Company has the right to control the use of an identified asset. ROU assets represent the Company's right to use the underlying asset for the lease term and lease liabilities represent the Company's obligation to make lease payments arising from the lease. ROU assets and liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term, including payments at commencement that depend on an index or rate. Most leases in which the Company is lessee do not have a readily determinable implicit rate, so an incremental borrowing rate, based on the information available at the lease commencement dates, is utilized to determine the present value of lease payments. When a secured borrowing rate is not readily available, unsecured borrowing rates are adjusted for the effects of collateral to determine the incremental borrowing rate. Lease expense and lease income are recognized on a straight-line basis over the lease term for operating leases.

The Company has lease agreements with lease and non-lease components and has elected the practical expedient to combine lease and non-lease components for certain classes of leases, such as office buildings. For classes of leases in which lease and non-lease components are not combined, consideration is allocated between components based on the stand-alone prices.

The Company's lease agreements do not contain any material residual value guarantees, material restrictions or material covenants. There are no material lease transactions with related parties. Because risk is minimal, the Company does not take any significant actions to manage risk associated with the residual value of their leased assets.

The Company's lease agreements are primarily equipment and real property leases, including land and office facility leases. The Company's lease terms may include options to extend or terminate a lease when it is reasonably certain that those options will be exercised. The Company has elected an accounting policy that exempts leases with terms of one year or less from the recognition requirements of ASC 842.

The components of lease cost, included in Operation and maintenance on the Company's Statements of Income, were as follows:


	Year Ended December 31,
	2021		2020
	(in millions)
Operating lease cost	$	1	$	1
Short-term lease cost	1		1

Total lease cost	$	2	$	2

Supplemental balance sheet information related to leases is as follows:


	December 31,
	2021			2020
	(In millions, except lease term and discount rate)
Assets:
Operating ROU assets (1)	$	2		$	2
Total leased assets	$	2		$	2
Liabilities:
Current operating lease liability (2)	$	1		$	1
Non-current operating lease liability (3)	1			1
Total lease liabilities	$	2		$	2

Weighted-average remaining lease term (in years) - operating leases	13.0			6.0
Weighted-average discount rate - operating leases	3.6		%	3.62		%

(1)Reported within Other non-current assets in the Balance Sheets.

(2)Reported within Accrued liabilities in the Balance Sheets.

(3)Reported within Other non-current liabilities in the Balance Sheets.

As of December 31, 2021, maturities of operating lease liabilities were as follows:


	(in millions)
2022	$	1
2023	1
2024	—
2025	—
2026	—
2027 and beyond	1
Total lease payments	$	3
Less: Interest	1
Present value of lease liabilities	$	2

Other information related to leases is as follows:


	Year Ended December 31,
	2021		2020
	(in millions)
Operating cash flows from operating leases included in the measurement of lease liabilities	$	1	$	1

(16) Subsequent Events

Management performs a review of subsequent events for any events occurring after the balance sheet date but prior to the date the financial statements are issued. The Company's management has performed a review of subsequent events through March 16, 2022, the date the financial statements were issued.